Classifications

• • G—PHYSICS
  • G01—MEASURING; TESTING
  • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
  • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
  • G01V1/28—Processing seismic data, e.g. analysis, for interpretation, for correction
  • G01V1/36—Effecting static or dynamic corrections on records, e.g. correcting spread; Correlating seismic signals; Eliminating effects of unwanted energy
  • G01V1/364—Seismic filtering
• • G—PHYSICS
  • G01—MEASURING; TESTING
  • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
  • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
  • G01V1/40—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
  • G01V1/42—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging using generators in one well and receivers elsewhere or vice versa
• • G—PHYSICS
  • G01—MEASURING; TESTING
  • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
  • G01V2210/00—Details of seismic processing or analysis
  • G01V2210/10—Aspects of acoustic signal generation or detection
  • G01V2210/16—Survey configurations
  • G01V2210/161—Vertical seismic profiling [VSP]
• • G—PHYSICS
  • G01—MEASURING; TESTING
  • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
  • G01V2210/00—Details of seismic processing or analysis
  • G01V2210/60—Analysis
  • G01V2210/66—Subsurface modeling

Definitions

• This invention relates generally to seismic surveying and processing of seismic data, and more particularly to combining vertical seismic profiling and reverse seismic data to obtain enhanced seismographs of the earth's subsurface formations from prior 3D data.
• VSP vertical seismic profile
• RVSP reverse vertical seismic profile
• VSP and RSVP methods have been known in the art.
• the present invention provides a method wherein the VSP and RVSP surveys are performed by reversing the placements of the seismic sources and receivers and then combining the two (2) sets of data to obtain certain transfer functions, which are then utilized to obtain enhanced seismographs from 3D data.
• the present invention provides a method of obtaining and processing seismic data to obtain enhanced geophysical maps from 3D seismic data.
• a first set of data is obtained from a vertical seismic profile (VSP) survey and a second set from reverse seismic profile survey by reversing the locations of the sources and receivers of the VSP survey.
• the two sets of data are combined to determine a transfer function or model, which is then applied to a set of 3D seismic data to obtain a seismic map of the area surveyed for the 3D data.
• Figure 1 is a schematic diagram of a vertical seismic profile survey method according to one embodiment of the present invention.
• Figure 1 A shows the distance/depth relationship of a source and receiver.
• Figure 2 is a schematic diagram of a reverse vertical seismic profile survey geometry wherein the locations of the acoustic sources and receivers are reverse from the locations of Figure 1 .
• Figure 3 shows representative downgoing and upgoing waves arranged along increasing time for a particular offset.
• Figure 4 shows an aerial view of an RSVP survey.
• Figure 5 shows a vertical view of the source-receiver layout corresponding to the layout of Figure 4.
• Figure 6 shows an equal azimuth survey layout.
• Figure 7 shows representative gathers after partitioning the data into upgoing and downgoing waves.
• Figure 8 shows a cross-well comparison of the upgoing and downgoing waves.
• Figure 9 shows a survey method wherein sources are activated in a deviated well with the seismic detectors at the surface.
• Figure 10A - 10B show examples of power spectra for the upgoing and downgoing waves.
• Figure 1 1 is an example of amplitude decay at frequencies at different times.
• Figure 12 is a flow chart of steps taken in a comparison process according to one method of the present invention.
• FIGS 13 and 14 show that wavelet in the cepstra domain is separated from response of reflect on series.
• Figure 15 shows example data collected in a wellbore at various depths.
• two (2) sets of data are gathered: one set with vertical seismic profile survey and the second with reverse vertical seismic profile survey, or one set of data representing the upgoing wavefield and another set of data representing the downgoing wavefield.
• the two (2) sets of data are then combined to obtain a transfer function, which is utilized to obtain enhanced seismographs of the earth's subsurface from 3D data.
• Figure 1 shows a type of commonly used vertical seismic profile survey method.
• a plurality of seismic wave detectors 1 10a - 1 10c (geophones, three component phones, or hydrophones) are placed in a wellbore 1 1 1 formed from a surface location 1 12.
• a seismic or acoustic source 120 is activated or set off at a plurality of spaced-apart locations at the surface 1 12, such as locations 121 a and 121 b.
• the receivers 1 10a - 1 10c detect the sound waves reaching the receivers, in response to the seismic waves generated by the sources 120.
• the receivers 1 10a - 1 10c provide signals representative of the detected waves, which signals are processed as more fully described below.
• the downgoing acoustic waves are marked “D” while the downgoing waves which arrive at the detectors after having been reflected from bed boundaries are marked “R.”
• the raypath for a given velocity medium may be expressed as:
• V V 0 + a z
• V is the acoustic velocity of the formation
• V 0 is the initial acoustic velocity
• z is the depth
• a is the acceleration
• FIG 2 shows a reverse vertical seismic profiling survey according to the method of the present invention.
• the source 120 (which is preferably the same type of source as utilized in the VSP survey of Figure 1 ) is placed at the locations previously occupied by the receivers 1 10a - 1 10c and the receivers (denoted as 1 10) are placed at the locations previously occupied by the source 120 shown in Figure 1 .
• the direct arrivals are marked "D” while the reflected arrivals are marked "R” .
• the direct arrivals "D” as well as the reflected arrivals "R” have the exact raypaths for the upgoing as well as the downgoing waves, because the two (2) sets of data are obtained by reversing the locations of the same receivers and sources.
• the direct downgoing waves of Figure 1 and the direct upgoing waves of Figure 2 (both shown as “D” in their respective figures) are combined. These waves have identical travel paths but are opposite in at least the following characteristics:
• FIG 3 shows hypothetical downgoing and upgoing waves arranged along increasing time for a particular offset from the VSP and RVSP surveys performed as described above in reference to Figure 1 and Figure 2.
• Wavelets "A” represent the downgoing waves arranged along increasing time while wavelets “B” represent upgoing waves arranged along increasing time for a particular offset. Same arrangements can be made with common direct arrivals "D” and the reflected arrivals "R.”
• Figure 4 shows an areal view of the layout of the surface receivers according to one geometry for RVSP survey wherein the receivers 140 are arranged at the nodes A - A nm of a grid 150 with n rows and m columns.
• the grid 150 is arranged around the wellbore 141 .
• the seismic source 142 is activated at known depths inside the well 141 to record data by the receivers 140 at the nodes A*,*, - A nm of the grid 150.
• Figure 5 shows a vertical view of the source-receiver layout corresponding to the layout shown in Figure 4.
• the source 140 is activated at a plurality of depths 144a - 144r in the well 141 .
• the direct waves are denoted by "D” while the reflected waves are denoted by "R.”
• the locations of or the layout for the receivers and sources are reversed.
• the seismic wavelets are detected by receivers, placed at all of the locations previously occupied by the sources.
• the VSP and RVSP surveys are performed at an area of prior 3D-seismic survey or where seismic data will be acquired.
• the seismic survey may be on land or in a marine environment.
• An advantage of utilizing previously utilized 3-D survey positions is that common travel path traces can be created from the existing 3-D surveys.
• the "finite difference" technique which employs lowering of receivers from the surface in steps or intervals down to the maximum depth of interest can be utilized. This process can be stopped at various depths to produce only downgoing or downgoing plus upgoing waves.
• the collected data may be a full suite of prestack data for amplitude versus offset or determination amplitude versus offset (AVO) and inverse use. This method is more expensive and utilizes a larger area compared to the above-described first survey method.
• the data may be collected to produce maps of the immediate vicinity of the well over time. Such data can be used to calibrate 4-D surveys.
• Figure 6 shows an equal azimuth survey, wherein the RVSP data receivers are placed at spaced-apart locations 160a - 160k radially extending from the wellbore 161 .
• the radial lines 165a - 1651 are at equal angular distances.
• Figure 6 shows a layout with equal increments of azimuth, the azimuth being the angle the raypaths travel with respect to the true north.
• Figure 6 shows a 30-degree angular separation of adjacent radial lines 165a - 1651. Other radial separations may also be utilized.
• the locations of the sources and seismic wavelet detectors are reversed.
• Figure 7 shows representative gathers after partitioning the data into upcoming and downgoing waves. Specifically, Figure 7 shows partitioned (upgoing) waves at a particular azimuth (angle) as a function of offset. By comparing the upgoing waves with the downgoing waves as a function of the azimuth, time and space (offset), variant filters can be derived to scale prestack 3D data.
• Figure 8 shows a cross-well comparison of the upgoing and downgoing waves.
• sources are activated in the well 101 at locations 201 a-201 n in the well 201 and locations 202a-202n in well 202.
• Receivers are placed at spaced-apart locations 206a-206m at the surface.
• the direct waves are denoted by "D” while the reflected waves are denoted by "R.”
• the positions of source (201a-201 n and 202a-202n) and receivers (206a- 206m) are then reversed to obtain VSP survey data.
• Data acquired by the survey geometry shown in Figure 8 typically shows upgoing and downgoing response of the subsurface formations to the source.
• data can be partitioned to separately show upgoing and downgoing response of the data.
• Velocity information can be derived from the earth's cross-section.
• Figure 9 shows a survey method wherein sources are set off (activated) in a deviated well 220 while the seismic detectors are placed at spaced-apart locations 220a - 220k at the surface 21 1 to obtain one ( 1 ) set of data. The positions of the sources and receivers are then reversed to obtain the second set of data. The upgoing and downgoing waves are compared to derive a velocity model to image complex geological objectives.
• At least one ( 1 ) set of acoustic wave data is processed to obtain a transfer function, which is then applied to existing 3D data to obtain enhanced seismic maps of the earth's subsurface.
• the survey methods described herein are referred to as "Transfer Function” or “Tf” survey and the corresponding data collected is referred to as the Tf data.
• Tf Transfer Function
• a number of methods may be utilized to process the transfer function survey data. Exemplary processing methods are described below.
• Prestack data collection can provide estimates of amplitude versus offset (AVO) effects as a function of azimuth, which information may be utilized for 3D AVO prediction.
• AVO amplitude versus offset
• this invention relates to a method of seismic surveying and processing seismic data by utilizing Tf surveys.
• two (2) sets of recordings are made.
• the first set of recordings include placing seismic wave detectors in a wellbore at different depths to record acoustic waves emanating from a seismic sources located at or near the surface. This form of survey is typically called vertical seismic profile or (VSP) survey.
• VSP vertical seismic profile
• a second set of recordings is done by reversing the settings of the first recording, i.e., placing sources at positions previously occupied by seismic wave detectors and detectors at the location of the previously placed sources.
• the first set of recordings include downgoing components representing direct arrivals, other multiple reflections, and upgoing reflections from below the seismic wave detector depth.
• the second set of recordings include upgoing components representing direct arrivals, other multiple reflections, and downgoing reflections from below the source depth.
• the first seismic process step to be applied to the data is to perform wavefield separation.
• wavefield separation the upgoing and downgoing wavefields are split into two different data sets.
• Techniques similar to the method described in United States Patent No. 4,794,573 can be employed to perform wavefield separation. Other suitable techniques may also be utilized.
• Comparison sets include comparing downgoing wavefield of the first recordings with the upgoing wavefield of the second recordings. This process relies on the fact that these traces are gathered into duplicate wavepath traces with the same or substantially the same upgoing and downgoing wavepaths. The main difference being that the source wavelet w(t) decays in opposite manners and the upgoing wavefield response is reversed. This allows one to create matched output filters.
• S(f) is the frequency domain representation of s(t)
• P(f) is the power spectrum
• ⁇ (theta) is the phase at each frequency "f.” .
• P, (f) is a power spectrum of D(t) and P 2 (f) is a power spectrum of U(t) .
• the amplitude decay can be expressed as:
• Equation (vi) is used into Equations (i) and (ii), i.e., the power spectrum comparisons of identical travel paths. "Q" is observed to be a constant for most geological materials in the range of seismic frequencies.
• Figure 1 1 is an example of amplitude decay at frequencies at different times.
• Each frequency is then scaled to the level indicated by U(f) and store the sealer applied at each frequency.
• U(f) D(f)
• all loss of amplitude as a function of frequency is taken out.
• H(f) can then be applied to the existing seismic 3D data, and post-stack data before migration.
• N(f) is "white noise” added to prevent filter blow up.
• the filter H(f) implicitly describes the parameter "Q.”
• the keys to the comparison of data sets are: (a) compare upgoing versus downgoing same or substantially the same travel paths organized in increasing time; (b) use the stacking process to remove effects of noise; (c) scale dataset downgoing waves to match upcoming waves, (d) store sealers, and (e) apply them to 3D seismic data in a horizon consistent fashion.
• Examples of (five point) gates are: First compute the envelope function of each set. Let U t be the upgoing trace envelope function in time and let D t be the downgoing trace envelope function in time. Then:
• This scale envelope trace S(t) is applied to the existing 3D seismic data in a horizon consistent manner.
• the above process compensates amplitude losses suffered by the seismic waves on post-stack 3D data set.
• the post- stack 3D seismic data set is a representation of zero offset - P wave stack.
• a more rigorous processing method for use in the present invention is described below.
• the design of a single trace can be extended in the prestack domain.
• the original acquired data for the present invention is merged with the geometry of the 3D survey.
• the data are then sorted into common-offset volumes. Filters derived from the T f survey are applied along horizons on common-offset volumes, as a first step to data conditioning to accurately compensate for amplitude loss in time and (source) wavelet decay.
• T f survey data are first collected to represent the range of offsets described by d, d + *d, d + 2*d ... etc., where 'd' is an offset and '*d' is an increment of offset, and up to the farthest offset of the original 3D data set encompassing the well.
• T f data is processed through wavefield separation and arranged (gathered) into upgoing and downgoing waveforms having substantially identical wavepaths, of same offsets d, d + ⁇ d, d + 2 ⁇ d...etc.
• Data summations are performed along common upgoing and common downgoing sets of d, d + ⁇ d, d + 2 ⁇ d etc. Comparisons of common time gates are made in this process in the "quefrency domain" .
• Flow diagram of Figure 12 shows the route taken in the comparison process. The main steps are:
• Step 1 For each gate for each d, d + ⁇ d, d + 2*d... for upgoing and downgoing traces derive the frequency domain representations of the gate by a Fourier transform.
• Step 2 Take the natural logarithm (base e) of the frequency domain. This is a complex quantity, since the frequency domain is complex.
• Step 3 Take the inverse Fourier transform of the log frequency spectrum. This is called a “complex cepstrum” of the data in the “quefrency domain.”
• Filters are derived in this domain and can be transformed to time using steps 4 through 6 indicated on the flow chart of Figure 12.
• the "quefrency” domain is a kind of time domain in which the data are displayed as amplitude versus time values.
• the two basic characteristics of this domain that make it useful for seismic data processing for the method of the present invention are:
• S(f), R(f) and W(f) are the Fourier Transforms of S(t), r(t), w(t), respectively.
• convolution in the time domain is multiplication in the frequency domain.
• Figs. 13 and 14 show that the wavelet in the cepstra domain is separated from the response of reflection series.
• a minimum phase wavelet will have all its energy at positive frequencies, mixed phase on both positive and negative quadrants, and maximum phase in the negative quadrant. Thus, some judgment of the wavelet position is needed to extract the wavelet.
• D(q) - U(q) gives us the net waveform difference in the gate.
• steps 4 through 6 we convert the difference D(q) - U(q) which is [W, (q) - W 2 (q)], the residual wavelet difference.
• Step 4 Take the Fourier Transform of the complex cepstrum [W ⁇ l ) - W 2 (q)] to return to the log frequency domain.
• Step 5 Take the natural antilogarithm of the log frequency domain to give normal frequency domain.
• Step 6 Inverse Fourier Transform the frequency to the time domain.
• a filter is derived for every offset, time gate, and applied to pre-stack 3D data in an horizon dependent manner and the data processed using conventional 3D processing.
• the resultant 3D data has enhanced frequencies and therefore able to resolve objects better.
• a VSP filter may be created and applied to surface seismic data.
• VSP data gathered in the geophones in the well at the depths z**, z 2 , z 3 ,..., zn, see Fig.15.
• u,(t) be downgoing wavefield trace in the /-th receiver.
• u,(t) as an incident wavelet. Following this wavelet change from the first to the last receiver, we can observe its change according to high frequency loss.
• ⁇ is a noise level

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